Pretreatment of raw natural gas prior to liquefaction

ABSTRACT

High pressure raw natural gas is prepared for liquefaction by first removing water and acid gases and then expanding the gas from the wellhead pressure to remove shaft horsepower. The expanded gas is scrubbed with a C 4  rich liquid previously separated from the gas to remove heavy hydrocarbons and then further dried and passed to the liquefaction zone.

This is a continuation application of pending application Ser. No.641,119, filed on Dec. 15, 1975, now U.S. Pat. No. 4,070,165.

FIELD OF THE INVENTION

The invention relates to a separatory process for gaseous hydrocarbons.It more specifically relates to a method of purification and separationfor raw natural gas such as is found in Classes 62-12 to 62-41.

PRIOR ART

A large number of commercial processes are in use for treating andseparating raw wellhead gas. The individual elements or steps used inthe different processes are each well known to those skilled in the art,and most recent advances have been in the area of more efficientdesigns, combinations or usages of these known components. For instance,U.S. Pat. No. 3,393,527 (Cl. 62-16) presents a method of separatingheavier hydrocarbons from a natural gas wherein work is performedthrough expanding the gas. U.S. Pat. No. 3,653,220 (Cl. 62-22) presentsa process for recovering helium in which the raw gas is dried andtreated to remove CO₂ at high pressure. This process differs from thepresent invention by the partial decompression and preliminary coolingof the gas prior to its expansion in a power recovery turbine.

A large amount of literature exists as to individual operations for thetreatment of natural gas. For instance, the Engineering Data Book, 9thEd., published by the Natural Gas Processers Suppliers Association,Tulsa, Okla. gives a description and design estimate basis for manytypes of gas dehydration techniques including the use of liquids such asglycols, solid desiccants and expansion refrigeration. This samereference also has a section on treating natural gas to remove acidgases by the processes of chemical reaction, physical solution andadsorption. Many commercial processes used for drying, sweetening,recovering natural gas liquids, manufacturing liquefied natural gas andremoving carbon dioxide, hydrogen sulfide and nitrogen are described inthe section comprising pages 93-122 of the April 1971 edition ofHydrocarbon Processing.

SUMMARY OF THE INVENTION

The invention provides a process for pretreating raw wellhead gas whichreduces the liquefaction refrigeration power requirements by utilizingthe energy recovered in expanding the raw gas and which reduces thevolume of gas which must be dried in expensive desiccant beds prior toliquefaction. A broad embodiment of the invention comprises the steps ofsweetening and drying the raw natural gas at a pressure above 800 psig.,depressuring the gas to a pressure under 200 psig. in an energy recoverymeans delivering shaft horsepower, scrubbing the resultant depressuredgas with a lean hydrocarbon stream to remove hydrocarbons having two ormore carbon atoms per molecule, passing the remaining gas stream througha second drying operation to provide a gas stream suitable forliquefaction, stripping C₁ -C₃ hydrocarbons from the rich hydrocarbonstream formed by scrubbing the depressured gas stream and using aportion of the resultant liquid as the lean hydrocarbon stream.

DESCRIPTION OF DRAWING

The drawing illustrates the preferred embodiment of the invention. Astream of raw natural gas is removed from the wellhead 1 and transportedthrough line 2 at a pressure substantially equal to the wellheadpressure. This stream is first passed through a sweetening zone 3wherein acid gases such as H₂ S and CO₂ are removed. Preferably, this isperformed by countercurrent contacting with a stream of a lean aminesolution entering in line 5, and the resultant rich amine solution isremoved via line 6. The now sweetened natural gas stream continuesthrough line 4 to a first drying zone 7 wherein water is transferred tothe dry glycol entering in line 10 to form a wet glycol stream removedin line 9. The resultant stream of dried natural gas is then passedthrough line 8, which may be a rather lengthy gathering or transferline, to an expansion turbine 11. The enthalpy of the gas stream isreduced through expansion and the delivery of shaft horsepower to anenergy consuming device such as a compressor 12 in the downstreamliquefaction operation.

The depressurized gas is transported into a scrubber 14 through line 13and contacted with a lean hydrocarbon stream entering in line 15.Conditions maintained within the scrubber effect the transfer of somemethane and very substantial percentages of heavier hydrocarbons intothe lean hydrocarbon stream to form a rich hydrocarbon stream removed inline 22. This rich stream is then stripped in fractionation column 23 toremove methane in line 24. The remaining hydrocarbons pass via line 25into column 26, in which a stream of ethane removed in line 27 isseparated. Finally, the hydrocarbons enter column 29 through line 28,and a stream of propane is removed via line 30.

This fractionation sequence produces a stream of C₄ plus liquid removedin line 31. A net liquid product stream is diverted into line 32 andpassed into a splitter column 33, which produces a stream of relativelypure butane discharged through line 34. A stream of naphtha likecondensate is removed via line 20. The remaining portion of the C₄ plusliquid is cooled in a heat exchange means 35 and passed into thescrubber as the lean hydrocarbon stream.

A methane rich gas stream is removed from the scrubber through line 16and passed into a second drying zone 17. This is preferably a soliddesiccant type of drying operation. The resultant dry gas stream is nowsuitable for passage into a liquefaction zone 18, from which a liquidstream comprising methane is removed via line 21.

Those skilled in the art will recognize that a great many alternativesare available in the practice of various steps of this process. Theseare described in detail below. Many accessories and subsystems have notbeen shown for the purposes of clarity and simplicity. This drawing anddescription are therefore not intended to limit the scope of the broadembodiment of the invention to the specific arrangement illustrated.

DETAILED DESCRIPTION

Raw natural gas must be treated prior to its liquefaction for severalreasons. These include removing compounds which interfere with or hinderthe liquefaction process, the recovery of hydrocarbon liquids andmeeting the product specifications set for the products. For instance,the gas must be dried to prevent ice formation in the process duringcryogenic operations and hydrogen sulfide cannot be tolerated due to itstoxic nature. The present invention therefore finds utility in thepretreatment of natural gas to be liquefied.

Raw natural gas is often produced at a wellhead pressure of from 800psig. to 4,000 psig. or higher. Very high pressure gas is normallythrottled to a pressure of about 1500 psig. at the wellhead to allow theuse of more easily fabricated piping, flanges and valves. This gas isthen passed into a sweetening zone operated at conditions effective tocause the removal of acid gases including hydrogen sulfide and carbondioxide. These conditions will include a pressure near the wellheadpressure or the lower pressure of the throttled raw gas. This zone mayutilize any system which is capable of removing these gases effectivelydown to a level of less than 50 ppm. and which is economical at thishigh pressure. CO₂ is normally present to a greater extent in naturalgas than H₂ S. It is removed to prevent it from freezing out insubsequent cryogenic processing.

It is preferred that the sweetening zone comprises an amine treatingoperation wherein the raw gas is passed through a contactorcountercurrently to a liquid amine solution. The amine is used as anaqueous solution and has no selectivity for H₂ S or CO₂. Ethanolaminesare one of the most commonly used reagents and are well suited for gasesrich in heavier hydrocarbons. Diethanolamine (DEA) is used when the gasstream contains carbonyl sulfide which reacts irreversibly withmonoethanolamine (MEA). This type of sweetening is similar to thatperformed in the Girbotol process.

In MEA units the total acid gas pickup is normally limited to about 0.33moles of acid gas/mole of MEA. The concentration of the MEA is generallyheld within the 15 to 18 wt.% range to limit corrosion. DEA may be usedat concentrations of up to 25 wt.%. With both solutions the contactorsand the associated amine strippers will typically have from 18 to 22trays.

Other processes are also available for sweetening and well known tothose skilled in the art. For instance, the Sulfinol process uses asolvent composed of sulfolane (tetrahydrothiopene dioxide),di-isopropanolamine (DIPA) and water. Diglycolamine (DGA) atconcentrations ranging from 50 to 70 wt.% in an aqueous solution canalso be used to sweeten natural gas containing carbonyl sulfide and/orcarbon disulfide. DGA is sometimes preferred since it can be used incolder climates than the other amines.

Another grouping of processes are the hot carbonate type developed bythe U.S. Bureau of Mines. They employ an aqueous solution of potassiumcarbonate which is circulated through an absorber and regenerator at atemperature of about 230° to 240° F. The process is limited in that itcannot be used on a gas stream containing only H₂ S. The most popularhot carbonate processes contain a proprietary activator. These are knownas the Benfield process, the Catacarb process and theGiammarco-Vetrocoke process.

Sweetening may also be performed through the use of a process in whichthe H₂ S is reacted with a hydrated iron oxide and the iron oxide isthen intermittently regenerated or replaced. This method is mainly usedwith gases having a low concentration of H₂ S.

The sweetening zone may contain a separate system for the removal of H₂S. One system suitable for this is the Stretford process in which thegas is washed with an aqueous solution containing sodium carbonate,sodium vanadate, anthraquinone disulfonic acid and traces of chelatediron. Only small amounts of CO₂ may be removed by this process, butessentially complete removal of H₂ S is possible. The process may beoperated over a wide pressure range starting at a few inches of mercuryand is normally run at a temperature of from ambient to 120° F. Thehydrogen sulfide dissolves in the alkaline solution and is oxidized toelemental sulfur by reaction with the vanadate. The circulating liquidis regenerated by air blowing, and the sulfur forms a scum removed byfroth flotation.

Physical solvent processes also find application in sweetening. The morepopular processes use such solvents as anhydrous propylene carbonate, adimethylether of polyethylene glycol and methanol. The absorber is aconventional trayed or packed tower. Regeneration is by one or more ofthe following techniques: multi-stage flashing, low temperaturestripping with an inert gas, or heating and stripping with the liquidvapor.

Those skilled in the art will appreciate the fact that this has not beenan exhaustive description of the processes which may be used in thesweetening zone. For instance, sulfur compounds can also be removedthrough the use of adsorption techniques including molecular sieveprocesses. Further details of these processes may be obtained from thereferences previously cited.

The now sweetened natural gas, while at a pressure which is reduced fromthat at the wellhead only by the inherent pressure drops within thetransfer lines and sweetening zone and any throttling, is then passedinto a first drying zone which is also operated at this high pressure.Water is removed at this point to prevent the formation of hydrates intransmission lines and to meet water dew point requirements. The basicdehydration techniques include absorption using solid or liquiddesiccants and dehydration by expansion refrigeration. This may includeintentionally freezing out the water. In general any system capable ofdrying the gas down to about a -20° F. dew point may be used. However,it is preferred that the first drying zone effects the formation of astream of dried natural gas having a dew point of -40° F. (about ninepounds water per million SCF). A nominal -40° F. dew point gas will havedry pipeline walls at 900 psig. pressure and any temperature above 38°F. The degree of water removal necessary in the first drying zone willdepend on several factors including the ambient temperature to which thetransmission lines are exposed. Thus, in artic climates the nominal dewpoint (measured at 14.7 psia.) will have to be much lower than -20° F.

It is preferred that the first drying zone consists of a glycol typedrying system. The most commonly used glycols are triethylene glycol(TEG), diethylene glycol (DEG), and ethylene glycol (MEG). The basicelements to a glycol drying system are an inlet gas scrubber, a glycolgas contactor, a glycol regenerator and a heat-exchanger. The dryingprocess comprises pumping regenerated glycol to the top tray of acontactor (absorber) and removing water-rich glycol from the bottom ofthe contactor. This glycol is heat exchanged with regenerated glycol andpassed into the regenerator. The regenerator may be operated atatmospheric pressure within a temperature range of about 375° to 400° F.This mode of operation can produce regenerated TEG having aconcentration of 99.0 wt.%. A stripping gas at rates up to 14 scf/gallonTEG is used in the regenerator if higher glycol concentrations aredesired. Glycol circulation rates may vary from about 2 to 5 gallons ofglycol per pound of water to be removed. The countercurrent contactingmay be carried out over a range of temperatures, with operation at theminimum available cooling water temperatures below 120° F. beingpreferred. The recirculation rate and the number of trays used in thecontactor will vary depending on such factors as the desired dew pointdepression. Typical contactors have from four to eight or more trays.

Solid-desiccant dehydration operations normally use a material which isregenerated in two or more beds used on a swing basis. It is possible toreduce the water content of the gas to less than 1 ppm. with a soliddesiccant. As a result they are commonly used to dry gas prior tocryogenic processing and are preferred for use in the second drying zoneof the subject invention. The specific desiccant to be used depends onthe composition of the gas stream and the dew point required. Somedesiccants are adversely affected by acid gases, well treating chemicalsand heavier hydrocarbons. Activated alumina, silica gel andsilica-alumina beads are some of the more common suitable materials.Molecular sieves, such as a type 4A sieve, are another group of suitablematerials. Further details on the use of desiccants can be obtained fromstandard references including for instance U.S. Pat. No. 3,205,683.

Dehydration can also be performed through expansion refrigeration. Thismethod is not preferred since it lowers the pressure of the gas stream.However, it may be utilized when the available field pressure isextremely high. Often a hydrate inhibitor is injected eithercontinuously or intermittently. Ethylene glycol is the most commonlyused, with other inhibitors being diethylene glycol and methanol. Theglycol and its absorbed water are separated from the gas stream alongwith liquid hydrocarbons. U.S. Pat. No. 3,537,270 illustrates a naturalgas dehydration process using expansion and is representative of thelevel of the art.

The terms "sweetening zone" and "drying zone" are intended to refer toall functional means for performing these operations. It is consistentwith this that the zones may be combined. Therefore the removal of bothacid gases and water in a single integrated system is intended as withinthe scope of the invention. Some solvent and molecular sieve operationsare capable of removing both H₂ S and water from the gas. For instance,U.S. Pat. No. 3,837,143 (Cl. 55-32) describes the use of a dialkyl etherof a polyalkylene glycol ether containing 2 to 15 wt.% water as solvent,and U.S. Pat. No. 3,841,058 (Cl. 55-33) presents an improvement in theremoval of water and carbon dioxide by solid absorbents and theregeneration of the absorbents. There may also be included within or inconjunction with the sweetening and drying zones a means for removingnitrogen and thereby increasing the heating value of the gas. U.S. Pat.No. 3,791,157 illustrates one such nitrogen removal process.

Following the removal of acid gases and water, the remaining portion ofthe natural gas stream is passed into an energy recovery means in whichthe gas stream is depressured. The energy recovery means may be locateda substantial distance away from the first drying zone. This is becauseeconomics generally favor transportation of gases at an elevatedpressure. The energy recovery means may be of any type which willdeliver shaft horsepower and effect a reduction in the enthalpy of thegas stream. Energy can be effectively recovered down to a pressure ofabout 100 to 300 psig. Consideration must of course be given to thepressure desired for the subsequent scrubbing and liquefactionoperations. It is preferred that the energy recovery means driveequipment used in the liquefaction zone. It is also preferred that theenergy recovery means is a turboexpander. These devices are already inwidespread use and their design is well known to those skilled in theart. More specific information is available from standard referencesincluding the article on pages 227-234 of February 1973 edition of theJournal of Engineering for Industry.

The resultant low pressure stream of dried and sweetened natural gas isthen passed into a scrubbing zone in which it is countercurrentlycontacted with a lean liquid hydrocarbon stream. The purpose of thisoperation is to remove heavier hydrocarbons, a term which is intended torefer to all hydrocarbons having more than two carbon atoms permolecule. The scrubbing zone should remove over 50% of the ethane andsubstantially all of the propane, butanes, pentanes, etc. As used inthis context the term substantially all is intended to refer to theremoval of over 90 mol.% of each hydrocarbon. This results in theformation of a net gas stream rich in methane, but also containingnitrogen and ethane. This net gas stream is the charge stock for theliquefaction zone and should contain at least 80% methane. The volume ofthe net gas stream will normally be about 80 to 85% of the raw naturalgas. This is advantageous as it allows a reduction in the required sizeof the downstream second drying zone.

The design and operation of scrubbing zones is well known. It ispreferred that a vertical column containing five or more trays isutilized, but a packed tower may be substituted. Higher pressures favorthe transfer of the heavier hydrocarbons into the scrubbing liquid, andit is therefore preferred that the scrubbing zone is operated at apressure above 50 psig. A temperature of from about 60° F. to 200° F.should be maintained in the zone. As the scrubbing operation isexothermic, this may require the subcooling of one of the feed streamsor the provision of intermediate cooling means. It is preferred that C₄to C₆ hydrocarbons predominate in the scrubbing liquid and thathydrocarbons having more than 6 carbon atoms per molecule comprise lessthan 30% of the circulating mixture. A circulation rate of about 1 to 3moles of liquid per mole of incoming gas is normally utilized.

The scrubbing liquid is removed from the scrubbing zone as a resultantrich liquid hydrocarbon stream and passed into a fractionation zone.This zone may take one of several forms depending on the desiredproducts. It is preferred that the fractionation zone comprises threecolumns, each of which produces a relatively pure stream of methane,ethane and propane respectively. The methane stream from this zone maybe admixed with the net gas stream of the scrubbing zone. Alternatively,all three of these gases may be removed as a single stream, and thisstream if desired can be further fractionated. The conditions usedwithin the zone will of course vary with its configuration and may bedetermined by those skilled in the art. For instance, a rather complexmethod of fractionating natural gas components to remove heavyhydrocarbons is illustrated in U.S. Pat. No. 3,393,527.

In the subject process a portion of the resultant C₄ -plus lean liquidequal to the amount of its component materials picked up in thescrubbing zone is divided off. This amount is preferably split inanother fractionating column to yield a stream of butanes and a streamof liquefied condensate. The remaining portion of the fractionation zoneeffluent is then cooled and passed into the scrubbing zone as a leanliquid hydrocarbon stream used as the scrubbing liquid.

The methane-rich net gas stream formed in the scrubbing zone is passedinto a second drying zone. The nature of this zone may vary, but it mustbe capable of drying the gas down to a dew point of roughly -240° F. orbelow. Preferably, the dry gas stream produced in the second drying zonewill have a dew point of -260° F. A solid desiccant system such aspreviously described is therefore preferred, and especially preferredfor use are alumina and molecular sieves.

In accordance with the preceding description, the preferred embodimentof my invention may be characterized as a process for the treatment ofraw natural gas prior to liquefaction which comprises: passing a streamof raw natural gas having a pressure above 800 psig. through asweetening zone operated at conditions effective to remove carbondioxide and hydrogen sulfide therefrom and to thereby effect theformation of a stream of sweetened natural gas; passing the stream ofsweetened natural gas through a first drying zone operated at conditionseffective to remove water therefrom and to effect the formation of astream of dried natural gas having a dew point below -20° F.;depressurizing the stream of dried natural gas in an energy recoverymeans developing shaft horsepower to a pressure under 300 psig.;contacting the stream of dried natural gas with a lean liquidhydrocarbon stream in a scrubbing zone operated at conditions effectiveto cause the transfer of substantially all hydrocarbons having more thantwo carbon atoms per molecule into the lean liquid hydrocarbon streamand to effect thereby the formation of a methane-rich gas stream and arich liquid hydrocarbon stream; passing the methane-rich gas stream intoa second drying zone operated at conditions effective to remove waterfrom the methane-rich gas stream and to effect the formation of a drygas stream having a dew point below about -240° F. and suitable forpassage into a liquefaction zone; passing the rich liquid hydrocarbonstream into a fractionation zone operated at conditions effective toremove hydrocarbons having from one to three carbon atoms per moleculefrom the rich liquid hydrocarbon stream and to effect thereby theformation of a C₄ -plus liquid hydrocarbon stream; and dividing the C₄-plus liquid hydrocarbon stream into two portions and passing one of theportions into the scrubbing zone as the lean liquid hydrocarbon stream.

The dry gas stream produced in the second drying zone will normally besuitable for insertion directly into a liquefaction zone. Presentlythree basic cycles for the liquefaction of natural gas are known tothose skilled in the art. These are generally referred to as the CascadeCycle, the Multi-Component Refrigerant Cycle and the Expander Cycle.Each is described in some detail in U.S. Pat. No. 3,724,226 (Cl. 62-39).These processes are each subject to much variation. Further examples anddetails of liquefaction methods may be obtained by referring to U.S.Pat. Nos. 3,254,495; 3,315,477 and 3,763,658.

I claim as my invention:
 1. A process for the treatment of raw naturalgas prior to liquefaction which comprises:(a) passing a stream of rawnatural gas having a pressure above 800 psig. through a sweetening zoneoperated at conditions effective to remove carbon dioxide and hydrogensulfide therefrom and to thereby effect the formation of a stream ofsweetened natural gas; (b) passing the stream of sweetened natural gasthrough a first drying zone operated at conditions effective to removewater therefrom and to effect the formation of a stream of dried naturalgas having a dew point below -20° F.; (c) depressurizing the totalstream of dried natural gas in an energy recovery means developing shafthorsepower to a pressure under 300 psig; (d) contacting said totalstream of dried natural gas possessing a pressure of less than 300 psig.with a lean liquid hydrocarbon stream in a scrubbing zone operated atconditions effective to cause the transfer of substantially allhydrocarbons having more than two carbon atoms per molecule into thelean liquid hydrocarbon stream and to effect thereby the formation of amethane-rich gas stream and a rich liquid hydrocarbon stream; (e)passing the methane-rich gas stream into a second drying zone operatedat conditions effective to remove water from the methane-rich gas streamand to effect the formation of a dry gas stream having a dew point belowabout -240° F.; (f) passing the rich liquid hydrocarbon stream into afractionation zone operated at conditions effective to separatehydrocarbons having from one to three carbon atoms per molecule from therich liquid hydrocarbon stream and to effect thereby the formation of aC₄ -plus liquid hydrocarbon stream; and, (g) dividing the C₄ -plusliquid hydrocarbon stream into two portions and passing one of theportions into the scrubbing zone as the lean liquid hydrocarbon stream.